With global oil production moving from plateau to decline, worldwide reserves of natural gas take on added importance. Increasingly, natural gas is viewed as a vital alternative energy source because it is plentiful and burns cleaner than other fossil fuels.
Methane is the primary component of natural gas. It is believed that methane is produced during the conversion to coal from peat, which is formed by continuous sub-aqueous deposition of plant-derived organic material in environments where the interstitial waters are oxygen-poor. In addition to methane, lesser amounts of other compounds such as water, nitrogen, carbon dioxide, and heavier hydrocarbons, and sometimes small amounts of other fluids such as argon and oxygen, can be found within the carbonaceous matrix of the coal formation. The gaseous fluids produced from coal formations are often collectively referred to as “coalbed methane.” Coalbed methane typically comprises more than about 90 to 95 volume percent methane. According to the U.S. Geological Survey, the reserve of such coalbed methane in the United States and around the world may be over 700 trillion cubic feet and over 7,500 trillion cubic feet, respectively. Most of these reserves are found in coal beds, but significant reserves are also found in other solid carbonaceous subterranean formations.
After natural gas is extracted from coalbeds but before it can be transported through the pipeline to a refinery, it must undergo a complicated process at or near the wellhead to remove various corrosion-causing contaminants. Depending on the well location and the geological conditions that created the natural gas in the first place, the raw gas emerging from the wellbore usually contains various amounts of water vapor; natural gas liquids such as ethane, propane and butane; hydrogen sulfide; carbon dioxide; helium; nitrogen; and other compounds. Various other contaminants are often introduced into the raw gas during the drilling and extraction of such gas from the coal seams. These other contaminants may include, for example, a pad fluid that is pumped down the wellbore into the coal-containing formation to initiate and propagate fractures in the formation. They may further include soaps and chemicals that are introduced into the wells to enhance production, especially during the “workover” of a wellbore when the well has reached the natural, downward slope of its production curve.
The process through which the raw natural gas is perliminarily purified at or near the wellhead is termed “field processing.” Field processing is carried out with clusters of machines. Each cluster typically includes one or more slug catchers, one or more compressors, a dehydrator, as well as one or more process water tanks. In certain field processing procedures, the raw gas first passes through a “slug catcher,” which roughly separates the liquid and gas phases. The liquid phase, which comprises essentially water and salts, is then sent to the process water tank, where the water may be treated and/or released into the ground. The gas phase is filtered to reduce the presence of pipeline scale that is introduced by the drilling equipment, and coal fines that inevitably accompany the raw gas as it is released from the fractured coal beds. The filtration in the slug catcher may be carried out with, for example, PECO™ PCHG-536 filter cartridges.
Downstream from the slug catcher, the extracted natural gas usually passes through a compressor, which may be either a reciprocating compressor or a rotary compressor. A reciprocating compressor comprises a cylinder and a piston. Compression is accomplished by the change in volume as the piston moves toward the “top” end of the cylinder. As the gas volume is decreased, there is a corresponding increase in pressure. Reciprocating compressors are thus known as positive-displacement-type compressors. Examples of reciprocating compressors include ARIEL™ reciprocating compressor JGK/4.
The gas stream from the slug catcher may instead pass through a rotary compressor, for example, a rotary screw compressor, which is likewise a positive-displacement compressor. There are several types of rotary screw compressors, including the rotary screw, lobe, and vane compressors. These compressors are described, for example, in U.S. Pat. Nos. 6,506,039, 6,217,304, and 6,216,474, the disclosures of which are incorporated herein by reference. A rotary screw compressor usually comprises one set of male and female helically grooved rotors, a set of axial and radial bearings, and a slide valve, all of which are encased in a common housing. As the rotors begin to un-mesh, the male rotor lobe rolls out of the female rotor flute. The volume vacated by the male rotor is then filled with gas. After the suction step, the compression process begins, during which the rotors continue to rotate and mesh together along the bottom, as the male motor lobe moves into the female flute and reduces the volume in the flute. The compression process continues until the compressed gas is discharged through the discharge port.
The compressors can be either single-stage or multiple-stage compressors. Multiple-stage compressors have a minimum of two pistons, and require two or more stages to reach the final output pressure, the output of one stage being the input to the next. Cooling the air between stages improves compressor efficiency.
Alternatively, a compressor of either type, typically a rotary screw compressor, may be placed upstream from the slug catcher as a wellhead booster, especially when the natural gas field exhibits declining pressure. Rotary screw compressors are often used for this purpose because they are designed for low pressure applications with inlet pressures up to 100 psig and discharge pressures up to 350 psig. In this case then, the gas stream entering the slug catcher already has reduced volume and increased pressure as compared to when it has first emerged from the wellhead.
Most if not all compressors are designed to operate with lubrication, although the specific ways lubricating oils are introduced depend on the compressor type. For example, the lube oil for a rotary screw compressor is injected in several locations with the main oil injection port, feeding the rotors directly and with smaller lines feeding to the points for seals and bearings. Injected oil will then drain the rotors where it combines with the gas, and the gas/oil mixture is then discharged from the compressor. On the other hand, for a reciprocating compressor, the lubricating oil is fed directly to the cylinder parts, including the pistons, piston rings, cylinder liners, cylinder packing and valves. Sometimes, the lubricating oil is also used as a coolant for the compressor cylinders and the running parts such as the main bearing, wristpin, crankpin, and crosshead pin bearings.
At or near the wellheads, the engines used to drive the compressors are typically natural gas engines, largely due to the ready access to natural gas and the often remote locations of these fields. This approach eliminates the need to transport fuels to, or otherwise provide means to power, the engines in remote areas. Examples of natural gas engines used in the field include the WAUKESHA™ engines.
Despite the initial phase separation in the slug catcher, the gas stream flowing into the downstream machines continues to be contaminated with water vapor. This is because natural gas produced from low-pressure wells normally has large amounts of saturated water vapor entrained therein. It is also thought that gas from newly installed wells may even be “wetter.” Dehydration thus must first occur before the wet gas enters the pipeline, because water is the predominant cause of corrosion and other water-related damage in pipelines and storage containers. Dehydration of the natural gas can take place by either of two processes: absorption or adsorption. Absorption occurs when the water vapor is taken out by a dehydrating agent. Adsorption occurs when the water vapor is condensed and collected on the surface.
The most common gas dehydration system and an example of absorption dehydration is a glycol dehydrator. The process of glycol dehydration is described, for example, in U.S. Pat. Nos. 5,453,114, 6,004,380, 5,536,303, 5,167,675, and 6,238,461, the disclosures of which are incorporated herein by reference. In this system, a liquid glycol desiccant serves to absorb water from the gas stream. Glycol has a chemical affinity for water. Thus, when in contact with a stream of water-containing (or wet) natural gas, the glycol “steals” the water out of the gas stream. Glycol solutions that may be used as liquid desiccants include, for example, diethylene glycol (DEG), triethylene glycol (TEG) and tetraethylene glycol. These glycol solutions are brought into contact with the wet gas stream in a contactor, wherein the glycol solutions absorbs water from the wet gas. The glycol fluid may be cooled by a cooler situated in the dehydrator itself, or after the compressors but before the dehydrator. As the water-logged glycol particles become heavier and sink to the bottom of the contactor, they can be removed form the contactor. The glycol solution is then put through a specialized boiler designed to vaporize only the water out of the solution. While water has a boiling point of 212° F., glycol does not boil until 400° F. This boiling point differential makes it relatively easy to “dry” the glycol solution, allowing it to be regenerated for future use. The ability to regenerate the glycol solution is particularly important in field processing of natural gas because the wellheads are often in remote locations.
Solid-desiccant dehydration, which constitutes an example of adsorption, provides another way of removing water vapor from wet natural gas. Solid-desiccant dehydrators usually comprise two or more adsorption towers filled with one or more solid desiccants. Typical desiccants include, for example, activated alumina and granular silica gel materials. As wet natural gas passes through the desiccant towers, from top to bottom, the water vapor is retained by the desiccant particles, leaving the “dry” or “drier” gas to exit via the bottom of the tower. While solid-desiccant dehydrators can be more effective than glycol dehydrators, they are not widely used because of the limited capacity and low saturation thresholds of the desiccants, and the need for frequent regeneration. Some solid desiccants, once saturated, cannot be regenerated to remove water, and thus must be discarded. The added burden of disposal, together with the storage and transportation difficulties, make solid desiccant systems impractical for natural gas field processing. The present invention therefore relates to situations where a liquid desiccant, especially a glycol desiccant, is in the dehydrator.
The dehydrator tends to become the collection point where a variety of materials come together. These materials may include those that had originally been part of the extracted natural gas but have yet to be removed. These materials may also include those that are introduced into the gas as the result of upstream processing steps. For example, the compressors and the natural gas engines that power those compressors often introduce materials such as mineral oils and chemicals form their lubricants and additives. These materials then cling to the natural gas as the latter reaches the dehydrator. It has been found that these contaminating materials, together with other remnants such as soaps, residual pipeline scale and coal fines, substantially emulsify under the wet gas stream. Thick emulsions and sometimes even sludges would form, clogging the dehydrators and other downstream machines, and causing the pressures therein to rise unacceptably. The thick emulsions may prevent the flow of glycol desiccants to the reboiler unit where the desiccants may be regenerated or recycled for future use. They may also prevent the proper channeling of the processed gas to the pipeline. Consequently, the dehydrators and other downstream machines must be cleaned out, and the glycol supplies must be replaced frequently, to avoid damaging the draining mechanisms and the machines housing these mechanisms. These requirements are undesirable, from both economic and practical standpoints, especially because field processing of natural gas mostly takes place in remote areas.
To remove the emulsion buildups, it is theoretically possible to install additional components or machines upstream from the dehydrators that would demulse by settling, heating, centrifugation, or subjecting the emulsions to electrical fields. However, most water-in-oil emulsions, such as those typically formed in the dehydrators, are too stable to be broken solely by the mechanical processes mentioned above with adequate timeliness. The use of chemical demulsifiers has proven more satisfactory in other instances where water-in-oil emulsions are problematic.
Demulsifiers are typically added to oil formulations to facilitate the separation of water containments from the oils and oil-soluble additives. They tend to concentrate at the oil-water interface and promote coalescence of the water droplets. The use of demulsifiers to break up water-in-oil emulsions is known, just as it is known that the presence of water-in-oil emulsions often leads to corrosions and to the growth of microorganisms in the water-wetted parts of the pipelines and storage tanks.
Desirable properties in demulsifiers include: (1) rapid breakdown into water and oil with minimal amounts of residual water in the oil phase; (2) good shelf-life; and (3) easy preparation. Certain nitrogen-containing compounds are known to be suitable demulsifiers for water-in-oil emulsions. For example, U.S. Pat. No. 4,153,564 disclosed demulsifiers that were the reaction product of an alkenylsuccinic anhydride or acid and an aniline-aldehyde resin, and the reaction product of an alkenylsuccinic anhydride and an aromatic trazole. U.S. Pat. No. 4,743,387 disclosed certain polyoxyalkylenediamines are demulsifiers. These nitrogen-containing demulsifiers were typically made by condensation of the amino groups with the carboxylic entities of acids. The long polyether chains and bulky 3-D structures of acids were found to be particularly suitable characteristics in demulsifier precursors.
Phosphorus-containing compounds are also known to have demulsifying properties in some instances, for example, in U.S. Pat. No. 4,229,130.
Other known water-in-oil demulsifiers include polyalkylene glycol and its derivatives. For example, U.S. Pat. No. 4,374,734 disclosed using polyoxypropylene polyol to break water-in-oil emulsions, wherein the emulsions were formed as a result of surfactant flooding in a process related to oil production from wells. The preferred molecular weights for the polypropylene polyols were said to be between 2,000 to 4,500. U.S. Pat. No. 3,835,060 taught conventional demulsifiers such as polyoxyalkylene glycol and polyoxyethylene-polyoxypropylene block polymers. U.S. Pat. No. 3,577,017 disclosed water-in-oil demulsifiers comprising ultra-high-molecular-weight (at or above 100,000) polymers. The polymers of that invention were selected from polyoxyalkylene polymers and copolymers of monomeric alkylene oxides having a single vicinal epoxy group. Furthermore, U.S. Pat. No. 5,407,585 disclosed a water-in-oil emulsions demulsifier that was a derivative or adduct of a high-molecular-weight polyalkylene glycol and ethylene oxide or diglycidyl ether. Methods of making polyoxyalkylene glycols are known in the art. For example, pending U.S. patent application Ser. No. 10,524,555 (published as U.S. 2006/0167321) disclosed a process of making such a copolymer by distilling water out of a reaction mixture comprising tetrahydrofuran and alpha, omega diols in the presence of a heteropolyacid and a hydrocarbon. The disclosures of the cited patent applications are incorporated herein by reference.
Demulsification, though important, is however not the sole concern at remote field processing sites. Further considerations should be given to formulating a set of lubricating oils that are compatible for the compressors as well as the engines that power those compressors. This is because, at these remote sites, it is desirable to use the same oils to lubricate the compressors and the engines.
Conventional lubricating oils are machine-specific. For example, with limited exceptions of some polyalphaolefin (PAO) and ester-based products, oils made with synthetic base stocks often cannot be mixed with products made with mineral oils even if they are designed for the same application. Moreover, some lubricants are incompatible because of differences in additive chemistry that might lead to undesirable chemical reactions, forming insoluble materials and depositing on sensitive machine surfaces. In its mildest form, adding the wrong lubricating oils to the equipment may lead to a degradation of lubricant performance. Even in that instance, however, unless the machine has never been previously oiled, the wrong lubricating oil is typically added to a vessel that already contains small amounts of the correct lubricating oil. Mixing the same grades of oils might not damage the engine, but it almost certainly will impede performance features that are provided by the intended lubricating oils. At the other end of the spectrum, adding the wrong oil to certain equipment may spell disaster, causing serve deposits, wear and filter plugging, and resulting in extensive damages.
A synchronized approach that lubricates compressors and engines with the same interchangeable oils would eliminate the risks associated with applying the wrong lubricating oils. This approach is especially desirable because it also avoids the need to stock different types of lubricating oils at or near the wellheads. This invention therefore further provides the method of using a single lubricating oil composition for the compressors and the natural gas engines that drive those compressors.